HomeMy WebLinkAboutRES2023-120 Electric Rate Tariff Sponsored by: Sorensen
Public Hearing: November 13, 2023
Postponed: November 13,2023
Approved: December 18, 2023
CITY OF SEWARD,ALASKA
RESOLUTION 2023-120
A RESOLUTION OF THE CITY COUNCIL OF THE CITY OF SEWARD,
ALASKA, AMENDING THE 2024 ELECTRIC RATES TARIFF TO
INCORPORATE RECOMMENDATIONS FROM THE 2023 RATE STUDY
TO SET ELECTRIC RATES AT A LEVEL TO MEET THE UTILITY'S
REVENUE REQUIREMENTS OVER THE NEXT THREE YEARS.
WHEREAS,the rate study was conducted by Mike Hubbard of The Financial Engineering
Company, an expert with 44 years of experience in electric ratemaking; and
WHEREAS, the rate adjustments recommended in the study are based upon a "cost of
service" allocation to the various customer classes and are designed to generate the revenues
needed to adequately operate the utility; and
WHEREAS, increasing customer rates is necessary because of expenses related to
deferred and ongoing maintenance, emerging technologies, future reliability and cybersecurity
standards, additional resources (staffing and/or consultants)to ensure safe and reliable operations,
rising inflation and other factors, including maintaining adequate cash flow; and
WHEREAS, public input on the proposed rates was received following a work session
with City Council on September 11, and this input was reviewed by The Financial Engineering
Company and adjustments to proposed rates were incorporated where practical; and
WHEREAS, the rate study recommends an increase of $0.06/kWh increase across all
customer classes beginning January 1, 2024; and
WHEREAS, this adjustment in rates will result in an overall increase of$36.00/month for
residential customers using an average of 600kWh/month; and
WHEREAS, this change to the 2024 Electric Tariff will continue to ensure fair and
equitable rates for all customers—where the "cost causer" is the "cost payer"—while also
safeguarding the financial health of the utility.
NOW,THEREFORE,BE IT RESOLVED BY THE CITY COUNCIL OF THE CITY
OF SEWARD,ALASKA,that:
Section 1. The City Council hereby authorizes amendments to the 2024 Electric Rates
Tariff based upon recommendations from The Financial Engineering Company.
Section 2.These tariff amendments will increase electric rates across all customer classes
by$0.06/kWh beginning January 1, 2024.
CITY OF SEWARD,ALASKA
RESOLUTION 2023-120
Page 2of2
Section 3. This resolution shall take effect ten (10) days upon adoption.
PASSED AND APPROVED by the City Council of the City of Seward, Alaska this 18th
day of December 2023.
THE CITY OF SEWARD,ALASKA
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Sue McClure, Mayor
AYES: Wells, Osenga, Crites, Barnwell, McClure
NOES: Finch, Calhoon
ABSENT: None
ABSTAIN: None
ATTEST:
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Kris Peck
City Clerk
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City Council Agenda Statement
Meeting Date: November 13,2023
To: City Council
Through: Kat Sorensen,City Manager
From: Rob Montgomery, General Manager Electric Utility
Subject: Resolution 2023-120: Amending The 2024 Electric Rates Tariff To Incorporate
Recommendations From The 2023 Rate Study To Set Electric Rates At A Level
To Meet The Utility's Revenue Requirements Over The Next Three Years
Background and justification:
The successful operation of an electric utility requires the ability to resolve several interrelated,yet
conflicting,goals. Central to these goals are rates. Set too high, and the utility risks losing load,or even
entire customers,to self-generation. But setting rates too low reduces the financial health of the utility or
runs the risk of not being able to keep up with maintenance and potential reliability issues. Low rates can
also lead to insufficient revenues for retaining key personnel or filling all staff positions.
Seward's electric utility is currently facing several financial challenges. The first is the payment of the
$10 million revenue bond that was taken out in 2022 to pay for deferred maintenance related to
infrastructure (Nash Road and substations).The utility begins paying the principal payment on the bond
in 2024,which is almost$1 million annually. The utility also has unbudgeted infrastructure work to
complete in the refurbishment of the Spring Creek Substation and several other capital projects on the
books over the next three years,including the replacement of old and deteriorating underground cable
serving residential areas such as Stoney Creek, Gateway/Dora Way, Old Mill,Nash Woods, and Questa
Woods. These projects are critical to providing these communities with reliable service.
Additionally,the utility must also meet forthcoming reliability and cybersecurity standards being set by
the state of Alaska;manage expenses related to deferred and ongoing maintenance; cope with the rising
costs of materials and supplies and inflation in general; ensure adequate cash flow related to debt service
coverage ratios and add necessary resources to adequately operate the utility moving forward.
Seward's rate study was conducted by Mike Hubbard of the Financial Engineering Company. Mr.
Hubbard is an expert with 44 years of experience in ratemaking.
The recommended adjustments in rates are based upon a"cost of service" allocation,meaning the "cost
causer"is the"cost payer."
City Council conducted a work session on the rate study on September 11, and input was received from
the public during the session. Some adjustments to Mr.Hubbard's study (outlined below)were made,
where practical,based on Council and public feedback.While these changes lowered the overall target
margin,labor costs and the contribution to the Major Repair and Replacement Fund(MRRF),one
expense was also added to the study that was not known until after the work session. This was an expense
related to shared right-of-way maintenance with Chugach Electric for the line between Cooper Landing
and Moose Pass.
Below are the updates made to the study following the September 11 work session:
186
1. Decreased the rate study's target margin from $500,000 to $300,000, which aligns with the utility's
target margin established in the 2021 rate study.
2. Decreased the rate study's MRRF contribution from $500,000 to $350,000.
3. Decreased the rate study's labor expenses on the proposed organizational chart from $835,000 to
$675,000.This reduction was the result of eliminating the Apprentice Operator position and combining
the Government/Railbelt Relations Coordinator and the Customer Relation-Communications
Coordinator into one job.
4. Increased the rate study $700,000 total ($400,000 in 2024 and $300,000 in 2026) to maintain the
transmission line right-of-way between Chugach Electric's Dave's Creek Substation near Cooper
Landing to Seward Electric's Lawing Substation near Moose Pass. Seward owns the high-voltage
transmission lines and poles within the right-of-way and CEA owns the lower voltage distribution lines
attached to the same poles.
The 2023 Rate Study recommends an increase in rates of $0.06 across all customer classes beginning
January 1, 2024. This adjustment to Seward's rates will result in an overall increase of$36.00/month for
residential customers using an average of 600kWh/month.
Comprehensive and Strategic Plan Consistency Information
This legislation is consistent with(citation listed):
Comprehensive Plan:
Strategic Plan:
Other:
Certification of Funds
Total amount of funds listed in this legislation: $
This legislation(✓):
✓ Creates revenue in the amount of: $ $10,612,704 in 2024
Creates expenditure in amount of. $
Creates a savings in the amount of: $
Has no fiscal impact
Funds are (✓):
Budgeted Line item(s):
Not budgeted
✓ Not applicable
Fund Balance Information
Affected Fund(✓):
General SMIC ✓ Electric Wastewater
Boat Harbor Parking Water Healthcare
Motor Pool Other
Note:amounts are unaudited
187
Available Fund Balance $
Finance Director Signature:
Attorney Review
✓ Yes Attorney -
Signature:
Not Comments:
applicable
Administration Recommendation
�✓ Adopt Resolution
Other:
188
COST-OF-SERVICE STUDY
r
SEWARD ELECTRIC SYSTEM
DRAFT
September 24, 2023
the Financial Engineering Company
191
Draft 9.21.2023
1. Includes clearing costs for transmission line between Daves
Creek and Lawing substations ($400,000 in 2024 and
$300,000 in 2026)
2. Reduce Margin from $500,000 to $300,000
3. Reduce contribution to MRRF from $500,000 to $350,000
4. New labor cost increases set at $675,000 plus benefits
192
SEWARD ELECTRIC SYSTEM
COST-OF-SERVICE AND RATE ANALYSIS STUDY
Table of Contents
Page
I. INTRODUCTION
Background................................................................. 1
Terms.......................................................................... 2
II. COST-OF-SERVICE STUDIES
TheProcess ................................................................. 6
Functionalization..................................................... 7
Classification........................................................... 7
Allocation ................................................................ 8
III. SES SYSTEM
Power Supply Costs ..................................................... 11
Rate Structure............................................................. 11
BaseRates............................................................... 11
Cost of Power Adjustment........................................ 12
IV. BILLING DETERMINANTS AND REVENUE REQUIREMENTS
Billing Determinants.................................................... 13
Revenue Requirements................................................. 15
V. REVENUE ADEQUACY AND COST ALLOCATION
Adequacy of Existing Rates .......................................... 20
Cost of Service............................................................. 21
Allocation Factors ........................................................ 21
Scenario Descriptions .................................................. 22
Results ........................................................................ 22
VI. CONSIDERATIONS AND OPTIONS
Revenue Requirements............................................... 25
Rates and Cost of Service............................................. 26
RateOptions................................................................ 26
Scenario 1 - Utility Retention................................... 26
Scenario 2 - Utility Sale........................................... 27
VII. SUMMARY AND RECOMMENDATIONS
Summary..................................................................... 28
Recommendations........................................................ 29
Table of Contents i
193
SEWARD ELECTRIC SYSTEM
COST-OF-SERVICE AND RATE ANALYSIS STUDY
Table of Contents - Continued
Tables and Figures
Table
1 Classification of Revenue Requirements............................ 8
2 Current Base Rates.......................................................... 12
3 Historical Number of Customers and Energy Sales............ 13
4 Billing Determinants ........................................................ 15
5 Assumed Capital Expenditures......................................... 17
6 Revenue Requirements..................................................... 19
7 Adequacy of Existing Rates............................................... 20
8 Scenario 1 Allocation Results ........................................... 23
9 Scenario 2 Allocation Results ........................................... 24
10 Rate Options and Bill Impact............................................ 27
Figure
1 Coincident / Non-Coincident Peak.................................... 4
2 Process............................................................................ 10
3 Historical Energy Sales..................................................... 14
Table of Contents
194
SEWARD ELECTRIC SYSTEM
COST-OF-SERVICE AND RATE ANALYSIS STUDY
Table of Contents - Continued
Appendixes
A-1 Derivation of Revenues - Existing Rates
A-2 Derivation of Revenue Requirements
B-1 Allocation of Revenue Requirements (Scenario 1 - Utility Retention)
B-2 Allocation of Revenue Requirements (Scenario 2 - Utility Sale)
C-1 Classification of Revenue Requirements (Scenario 1 - Utility Retention)
C-2 Classification of Revenue Requirements (Scenario 2 - Utility Sale)
D-1 Plant in Service
D-2 Functionalization/Classification of Plant
E Derivation of Peak
Table of Contents
195
I. INTRODUCTION
BACKGROUND
The successful operation of an electric utility (or any type of utility for that
matter) requires the resolution of several interrelated, yet conflicting, goals.
Central to these goals are rates. Set too high, and the utility risks losing load,
or even entire customers, to self-generation. But setting rates too low reduces
the financial health of the utility or runs the risk of not being able to keep up
with maintenance and potential reliability issues. Low rates can also lead to
insufficient revenues for retaining key personnel or filling all staff positions.
Setting rates too low for short periods can also lead to long-term problems.
Too often, "temporary" reductions in budgets that forego maintenance become
the norm. By the time maintenance becomes critical, large rate increases are
required to bring the utility back to safe and reliable operations.
All of these issues, whether influenced by high rates or low rates, can lead to
ratepayer discontent. If this discontent is strong enough, the sale of the utility
becomes a strong possibility. Here in Alaska, Chugach Electric's acquisition
of Anchorage Municipal Light 8s Power is the most recent example. Other
examples exist, however, including Golden Valley Electric Association
acquiring the electric utility of Fairbanks Municipal Utilities System, the City
of Thorne Bay selling its utility to Alaska Power Company, and the Alaska
Village Electric Cooperative acquiring Bethel Utilities and others.
Clearly, rate setting is no easy task, and both long- and short-term factors
must be taken into account. Thus when setting rates, budgets should be
established that consider the various activities required over the next several
years. In addition to on-going operations, the budget must consider:
• Prudent Maintenance. While it is sometimes easy to forego right-of-way
clearings and other similar activities that are not required immediately,
foregoing these can lead to increased damage during storm events or
playing "catch-up" later on. Sporadic maintenance may also lead to
higher costs if the work must be contracted out due to existing staff
being busy with other work.
• Emerging Technologies. Sufficient working capital is required to
implement capital improvements or programs that provide near- and
long-term benefits to consumers.
• Security. Both cyber security and security for the infrastructure are
now of more importance and must be part of any budget.
I. Introduction Page 1
196
• Staffing. Adequate staffing levels for safe and reliable operations must
be included. With emerging technologies and security becoming more
important, historic staffing levels may no longer be adequate. Staff
positions that are included in the budget but remain unfilled are a
strong indication that budgeted salary levels are inadequate to attract
qualified personnel.
• Debt Covenants. Lenders to municipal utilities such as Seward require
minimum cash flows be maintained through specified debt service
coverage ("DSC") ratios. Even if there is no debt, minimal cash flows
might restrict access to future debt.
• Impact on Ratepayers. All the above must be balanced with impacts on
ratepayers.
But simply setting the budget and then charging the same rate to all
customers can be discriminatory to some. Even if rates differ among the
various rate classes, modifying rates by the same amount can also be
discriminatory.
Consider for example, a utility that has numerous small customers and one
large, industrial customer that operates for only a short period of time each
year. Assume further that the industrial customer's load is large enough to
require the utility to install large equipment to deliver power to that
customer's facility. A single rate for all customer classes may result in other
rate classes paying for the additional infrastructure since the industrial
customer operates for only limited times.
Accordingly, a cost-of-service analysis is an integral part of any rate study
where revenue requirements are allocated to each rate class and rates then
set that will recover the required revenues. This process, described later in
this report, results in rates that fair and equitable such that the "cost causer"
is the "cost payer."
The last rate study performed by the Seward Electric System ("SES") was
completed in 2021. Since then, costs have significantly increased for a
number of items, deferred maintenance has been performed, and several large
capital additions have been made. Staff now believe that rates are inadequate
to fund on-going operations, and a rate review is now required. The Financial
Engineering Company was retained to perform this review, and this report
summarizes the analysis and findings.
TERMS
Certain terms are used in this report that may not be familiar to those not
closely associated with the power industry. These terms are described below.
I. Introduction Page 2
197
Enerqu
The total amount of power consumed over a given period. For example,
a 100-watt light bulb, if left on continuously, uses 2,400 watt-hours of
energy during a 24-hour period. During the entire year (8,760 hours),
876,000 watt-hours of energy are consumed.
Units: The unit of measurement is typically kilowatt-hours
(kWh) or megawatt-hours (MWh).
1 MWh = 1,000 kWh = 1,000,000 watt-hours
Demand, or Peak Demand
The maximum rate of consumption of power. Usually, this is measured
over a 15-minute period, but instantaneous demands are also used. If
in the previous example a second light is turned on for 15 minutes,
then the peak demand is 200 watts.
Units: The unit of measurement is typically kilowatts (kW) or
megawatts (MW).
1 MW = 1,000 kW = 1,000,000 watts
System Peak
The combined peak demand of all utility customers placed on the
utility.
Units: kW, MW
Coincident Peak ("CP")
The usage of power of a particular rate group at the time of system
peak.
Units: kW, MW
Non-Coincident Peak ("NCP")
The peak demand of a particular rate group. The non-coincident
peak of a rate group does not necessarily happen at the time of the
system peak. If the rate group's non-coincident peak occurs at the
time of its coincident peak, then the two are equal, otherwise (as is
usually the case) the non-coincident peak is greater than the
coincident peak.
Units: kW, MW
I. Introduction Page 3
198
Coincident peak and non-coincident peak are illustrated in the
following figure.
Figure 1
SES COST OF SERVICE STUDY
Coincident/Non-Coincident Peak
-Total5yste:~r LoEc
Load of 5"ng le Rate I- as_
is
O
J
a Class CP
2
Cl ass N CP
.........................................................................................................................:..........
...............................................................................................................................................
Billing Determinants
The amount of energy sales, demand sales, and number of customers
for each rate group during a year.
Units: kWh, kW-months, customer-months
Base Rates
Rates that are set by the utility to recover the annual revenue
requirements that are not associated with fuel or purchased power
costs. Base rates include a customer charge, energy charge, and
demand charge and are set through action by a governing body. Base
rates are in effect for periods of one or more years; whereas fuel and
purchased power costs are typically recovered through a separate
charge that changes on a monthly or quarterly basis.
I. Introduction Page 4
199
Cost of Power Adjustment ("COPA")
A rate that recovers the cost of generating fuel and purchased power.
SES purchases all of its power requirements from Chugach, who
charges a base rate and its own COPA. SES passes these charges on
to its customers at cost via the SES COPA.
I. Introduction Page 5
200
II. COST-OF-SERVICE STUDIES
THE PROCESS
Before one can understand the process of how a cost-of-service study is
performed, one must first understand the infrastructure of a utility and what
are the influencing factors in developing this infrastructure. To procure and
deliver power to a customer, the utility must:
• Construct a generation system or procure power from some source.
• Construct a transmission system to deliver the power from the
generating site to the distribution system.
• Construct a distribution system complete with poles, transformers, and
meters to deliver the power to the end user.
• Hire staff to operate and maintain the system and to perform
administrative duties such as meter reading, preparing and sending
out bills, and other activities.
Thus, the utility's functions can be categorized as those being related to
Generation/Production, Transmission, Distribution, Customer Accounts, and
Administrative. But what factors influence each of these functions?
The Generation system must be sized to meet total system peak (or, Coincident
Peak) along with adequate reserves. The Transmission system must also be
sized to meet the Coincident Peak as power is delivered from remote areas to
the system.
The Distribution system is, however, a bit more complex. Poles, wires, meters,
and transformers are, to a large extent, a function of how many customers
there are. But the size of wires and transformers are also a function of how
large a customer is since a customer with a larger load requires larger
equipment to carry the load. Thus, the Distribution system is sized to meet
both the number of customers and size of load. Since the distribution system
is not sized to meet the total system load but rather the load in the immediate
area, the Non-Coincident Peak is used.
Customer accounts, which includes meter reading, billing, and other related
activities, are influenced by the number of customers regardless of the size of
the customers' loads.
Recognizing these influencing factors, the National Association of Regulatory
Utility Commissioners ("NARUC") has developed and published a process for
II. The Process Page 6
201
allocating utility costs to the utility's rate classes so that a utility's rates are
not arbitrary or capricious toward any one or more rate classes. All Alaskan
electric utilities that are rate regulated by the Regulatory Commission of
Alaska ("RCA") must use the process set forth in the NARUC Manual when
adjusting base rates. Although SES' rates are not regulated by the RCA, the
methodologies set forth in the NARUC Manual are used herein.
In very general terms, the analysis is performed in a multi-step process.
These steps are:
1. Projecting the amount of customer months, energy sales, and
demand sales.
2. Projecting the utility's revenue requirements.
3. Functionalizing the revenue requirements into those being related
to generation, transmission, distribution, and other functions.
4. Classifying the functionalized revenue requirements into those
being related to energy, demand (coincident and non-coincident),
customer, or direct.
5. Allocating the classified revenue requirements to each rate class
based on the contribution of each class to that classifier.
6. Designing rates that will recover each rate class' allocated cost of
service.
The first two steps are described later in this report, whereas the next three
(Functionalization, Classification, and Allocation) are described in general
terms below.
FUNCTIONALIZATION
A utility's production, transmission, distribution and consumer
accounts expenses are functionalized through the Uniform System of
Accounts. Administrative and General expenses, interest expenses,
and other items are functionalized as either production, transmission,
distribution, or consumer accounts using the labor components of
expenses already functionalized, functionalized plant in service, and
other factors.
CLASSIFICATION
Once the revenue requirements are functionalized, they are then
classified as either demand-, energy-, or customer-related. At the risk
of over-simplification, the NARUC Manual prescribes the functionalized
revenue requirements to be classified as shown in Table 1. As one can
see, the classification mirrors the influencing factors described on the
preceding page for each function. Detailed classification methodologies
for the various line-item expense codes are provided in the NARUC
Manual with the goal of classifying in a fair and equitable manner. The
II. The Process Page 7
202
NARUC Manual is published for the use of all utilities nationwide and
acknowledges that certain deviations from the methods prescribed may
be warranted due to local conditions.
Table 1
SES COST OF SERVICE STUDY
Classification of Revenue Requirements
Functionalized Classification
Revenue Demand
Requirement Coincident Non Energy Customer
Coincident
Production x x
Transmission x
Distribution x x
ALLOCATION
The final step in the cost-of-service analysis is to allocate the classified
revenue requirements to each customer class (or rate group) based on
each class' respective use of the allocation. For example, energy is
typically allocated based on sales. If a particular class accounted for
30 percent of the sales, then 30 percent of the costs classified as
energy-related would be allocated to that class.
Energy- and customer-related expenses are fairly straightforward, but
demand allocations become much more complex since there are a
number of different methods that can be used. Some form of the
coincident and non-coincident peaks are typically used, with such
forms including the annual peak, average of the four peak months,
average of the twelve months over the year, average of the three
summer and three winter peak months, and so on.
Further complicating the matter is that a great deal of load research
must be conducted in order to estimate these class peaks with any
precision. Such research can be expensive, and the benefits of
obtaining the data can quickly be eroded by the associated costs. Load
research of comparable utilities and an analysis of billing demands can
be used in lieu of the expensive load research.
After the revenue requirements have been allocated to each class, the existing
rates are applied to the billing determinants (number of customers, energy
sales, demand sales) to determine if the rates recover less than or more than
the allocated cost of service. Rates are then adjusted accordingly.
It is important to understand that there are inherent inaccuracies in the
process, and it is not an exact science. The goal is to set rates such that they
11. The Process Page 8
203
are reasonably close to the allocated cost of service, thereby allowing other
factors to be considered. Such factors might include foregoing large rate
shocks to a particular class, economic development, and others.
IL The Process Page 9
204
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I The Process Page to
205
III. SES SYSTEM
POWER SUPPLY COSTS
SES receives all of its power supply from Chugach, although back-up
generation is maintained in the event of service disruptions. The monthly
CEA bill for power consists of a small customer charge, an energy charge, a
demand charge, and the fuel and purchased power adjustment ("FPPA"). The
first three rates are modified through a general rate proceeding with the RCA,
whereas the FPPA is adjusted quarterly based on CEA's fuel costs and
generating efficiencies. CEA reduces the overall bill by a fixed amount each
month in recognition of SES' share of the Bradley Lake Hydroelectric Project.
Chugach rates are regulated by the Regulatory Commission of Alaska ("RCA"),
and the utility has recently filed for a rate increase. Presentations by Chugach
indicate that the base rates (non FPPA) charged to SES will increase by
approximately 16.5 percent. When the FPPA is included and assuming it does
not change, the cost of power from Chugach is projected to increase by
approximately 6.5 percent. The overall process with the RCA takes
approximately a full year from the time of filing.
RATE STRUCTURE
SES has five primary rate groups and two additional sets of rates for Yard
Lights and Street Lights. Rates charged to each rate class are comprised of
two major components - Base Rates and COPA. Base rates are, in turn,
further subdivided into three sub-components, and each is described as
follows.
1. Base Rates. Implemented to recover costs of the system that are not
related to fuel or purchased power. Base Rates do not fluctuate during
the year and are changed only through Council action.
a. Customer Charge. A fixed dollar amount the customer must pay
each month regardless of how much energy is used. These rates
are implemented to recover some of the fixed, customer-related
costs of the utility such as carrying charges and depreciation of
transformers, meters, service connections, and part of the
distribution system as well as expenses related to meter reading,
billing, and customer service.
b. Demand Charge. A charge based on peak usage (in kilowatts, or
kW) during the month. These charges are used to collect part of
the demand-related costs of the system such as those associated
with production, transmission, and part of the distribution
III. SES System Page 11
206
plant. The demand charge is applied only to Large General
Service and Industrial customers.
c. Energu Charge. Used to recover the remaining revenue
requirements and charged based on energy usage by the
customer.
2. Cost of Power Adjustment. The COPA is implemented to recover all
purchased power costs. It is assessed on all energy used by a
customer.
Rates in effect are summarized in Table 2.
Table 2
SES COST OF SERVICE STUDY
Current Base Rates
Small General Large General
Residential Boat Harbor Industrial
Service Service
Customer($/month) 22.10 42.22 42.22 44.23 100.00
Energy($/kWh)
Summer 0.1217 0.1269
Winter 0.0851 0.0927
Annual 0.1103 0.0437
All Energy
First 200 kWh/kW 0.0761
Additional 0.0264
Demand($/kW-mo) 26.93 30.00
III. SES System Page 12
207
IV. BILLING DETERMINANTS AND REVENUE
REQUIREMENTS
BILLING DETERMINANTS
The number of customers and energy sales for the 2012 - 2022 time period
are shown in Table 3, and energy sales are summarized in Figure 3. In 2021,
SES established an Industrial rate class that included three customers, one
being the Alaska SeaLife Center which was at the time being served under a
Special Contract. Billing data is available for each of these customers from
2020 and is separated in the table. Prior to then, the three customers are
combined with the Large General Service rate class.
As can be seen, total energy sales have increased from the pandemic years
but are still lower than ten years ago. Billing determinants incurred during
2022 are used for this study, and these are summarized in Table 4.
Table 3
SES COST OF SERVICE STUDY
Historical Customers and Sales by Rate Class
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Customers(Average Annual)
Residential 2,058 2,067 2,084 2,100 2,114 2,000 2,023 2,045 2,059 2,068 2,086
Small General Service 500 503 508 514 530 480 506 530 543 558 574
Harbor 22 22 22 22 27 27 28 27 27 27 28
Lg Gen Svc/Sp Contract 95 97 96 97 100 93 92 84 92 89 82
Total 2,675 2,689 2,710 2,734 2,771 2,599 2,650 2,686 2,721 2,742 2,769
Percentage Increase(Decrease) 0.5% 0.8% 0.9% 1.4% -6_2% 1.9% 1.4% 13% 0.8% 1-0%
Energy Sales(000 kWh)
Residential 16,488 15,611 15,265 14,924 14,888 15,441 14,882 15,107 15,925 16,328 15,712
Small General Service 8,652 8,392 7,965 7,809 7,422 7,493 7,560 7,778 7,579 8,328 8,709
Harbor 1,443 1,625 1,455 1,717 1,908 1,709 1,758 1,435 1,612 1,720 1,868
Lg Gen Svc/Sp Contract
LGS 17,614 18,189 19,193
Industrial/Sp Contract 9,473 9,865 9,361
Subtotal 32,059 32,229 30,408 30,303 28,733 28,539 27,517 27,284 27,007 28,054 28,554
Street Lights 96 94 98 90 71 67 67 68 66 66 68
Total 58,738 57,950 55,190 54,843 53,103 53,249 51,784 51,673 52,268 54,495 54,911
Percentage Increase(Decrease) -1.3% -4.8% -0.6% -3.2% 0.3% -2.8% -0.2% 1.2% 4.3% 0.8%
IV. Billing Determinants / Revenue Requirements Page 13
208
Figure 3
SES COST OF SERVICE STUDY
Historical Energy Sales
(millions of kWh)
70
60
50
40
30
20
10
2012 2013 2014 2015 2016 2017 2018 2019 2C20 2021 2022
■Residemial ■Small General Service : HaHbor large General Service/Special Contract ■Street lights
IV. Billing Determinants / Revenue Requirements Page 14
209
Table 4
SES COST OF SERVICE STUDY
Billing Determinants
Average Number Energy Sales Average Billing
of Customers (MWh) Usage ❑emand
(kWh/cust-mo) (kW-months)
Residential
Summer 2,091 7,164 571
Winter 2,081 8,548 685
Total 2,086 15,712 628
Sm Gen Svc/Harbor
Summer 583 4,701 1,345
Winter 565 4,008 1,183
Total 574 8,709 1,265
Harbor 28 1,868 5,608
Lg Gen Svc 79 19,193 20,225 53,901
Industrial 3 9,361 260,038 24,128
Street Lights 6 68 940
Total 2,775 54,911 70,790
REVENUE REQUIREMENTS
The next step in the process is to establish the amount of revenues that must
be collected from rates. Typical rate studies are based on the projection of a
single year. However revenue requirements are expected to significantly
increase in the next several years due to two primary factors.
First, staff believes the utility is understaffed for reliable operations, and
existing salaries are inadequate to attract and retain quality personnel.
Therefore, current labor expenses are believed to be unrealistic and need to
be adjusted upward.
Second, several large capital expenditures are being planned, and such
additions will increase depreciation expenses. Part of the additions is planned
to be funded with debt, and interest expenses will also increase.
Accordingly, the 2022/2023 budget is used as the basis for this study but
with projections through and including 2026. Most budget line items are
increased at the assumed inflation rate of 2.5 percent per year, but many are
adjusted using specific assumptions. These assumptions are described as
follows, and the projections are summarized in Table 6 at the end of this
section and provided in their entirety in Appendix B-1.
IV. Billing Determinants / Revenue Requirements Page 15
210
1. Labor. Preliminary estimates by staff for the combined effect of
increased staffing and salaries was $835,000 per year. That
estimate has since been reduced to $675,000 per year, or 61.6
percent above that budgeted for 2023. All budgeted labor and
benefit amounts are increased by this percentage in 2024 and
increased with inflation thereafter.
2. Contracted Services - Transmission. The 2022 and 2023 budgeted
amounts are $800,000 and $500,000, respectively. This relatively
high amount reflects the clearing of right-of-ways and is expected to
be completed by the end of this year. The amount assumed for 2024
and thereafter is $200,000 per year plus inflation.
3. Transmission Clearing - Chugach recently informed SES that SES
would now be responsible to pay for its share of clearing the
transmission right-of-way between the Daves Creek and Lawing
substations. Chugach's estimate of the SES share is $400,000 in
2024, and this amount is included in the revenue requirements.
Clearing is expected to occur every 2 - 3 years, and an additional
$300,000 plus inflation is included in 2026.
4. Wholesale Power Costs. This line item represents wholesale power
purchases from Chugach. Since these costs are recovered through
SES' COPA, they are eliminated from the revenues requirements.
5. Contractual Services - General Operations. The 2022 budgeted
amount is $925,287 but decreases to $325,000 for 2023. On-going
amounts are assumed to be $350,000 in 2024 with inflation
thereafter.
6. Operating Supplies. The 2022 budget is $262,286 and decreases to
$50,000 for the 2023 budget. Projections are based on the lower
amount budgeted for 2023.
7. Operating Materials. The 2023 budget is $300,000 with no prior
amounts (budgeted or historical). The amount is increased to
$450,000 in 2024 with inflation thereafter.
8. General Fund Administrative Fee. The budgeted amount of
$1,035,780 for 2023 is held constant thereafter. Conversations
with City personnel did not reveal the basis for this number, and it
is recommended that the City review how this is charged to its
various departments.
9. Payment in Lieu of Taxes ("PILT"). This item was not included in the
budget but is still assessed to the utility. Historical amounts have
been in the range of $1 million, and this amount is included for
2023 and increased with inflation thereafter. Staff indicates that
the assessed amount is to be levied at the rate of 8 percent of all
revenues. It is noted that fuel costs are part of the Chugach bill,
and the assessment could vary with Chugach's fuel costs.
IV. Billing Determinants/ Revenue Requirements Page 16
211
10.Major Repair and Replacement Fund - Historically, SES (and other
City departments) have made annual contributions to this fund.
However, no contributions have been made over the past several
years, but such contributions should be made to lessen the reliance
on future debt. Preliminary analyses were based on a $500,000
annual contribution, but due to the impact on rates, the
contribution has been reduced to $350,000 per year plus inflation.
The amount is added to the revenue requirements for 2024 and
thereafter.
11.Depreciation. Depreciation expenses are based on depreciation
schedules of existing assets and assumptions regarding future
capital additions (explained later).
12.Motor Pool Rent. Assumed to decrease to $100,000 per year and
escalated at inflation.
13.Debt Service. Interest payments are based on actual schedules and
assumptions regarding future debt. Principal payments on debt are
excluded as an expense since the inclusion of depreciation on the
assets funded with debt would be a double counting of expense.
14.Capital Expenditures. The assumed future capital expenditures are
summarized in the following table. New debt is assumed to be a 20-
year note, amortized at 5 percent. Potential capital expenditures for
expanding office space required for additional staff are not included
at this time.
Table 5
SES COST OF SERVICE STUDY
Assumed Capital Expenditures
Depreciation Placed Funding
Project Into Cost
Life Source
Service
Nash Road Project/Substation 30 12/31/23 10,000.000 Debt
Spring Creek Sub 30 12/31/24 3,369.769 Debt
Stoney Creek Cable 30 12/31/23 250,000 Internal Capital
Old Mill93 Cable 30 12/31/24 256,250 Internal Capital
Gateivay/Dora Way Cable 30 12/31/24 230,625 Internal Capital
Questa Woods Cable 30 12/31/26 139,996 Internal Capital
Nash Woods Phase I Cable 30 12/31/25 262,656 Internal Capital
SectuityCameras-Ft Raymond 30 12/31/25 220,631 Internal Capital
RadiatorHoods-Ft Raymond 30 12/31/24 235,750 Internal Capital
On-going2024 20 12/31/24 102,500 Internal Capital
On-going2025 20 12/31/25 105,063 Internal Capital
On-going2026 20 12/31/26 107,689 Internal Capital
IV. Billing Determinants / Revenue Requirements Page 17
212
15.Target Margin. There are certain inherent inaccuracies in the
projection of both revenues and revenue requirements. Actual
expenses may be higher or lower than projected as might be actual
billing determinants (energy sales, billing demands, etc.). It is,
therefore, prudent to increase the revenue requirements by some
amount to take into account these inaccuracies.
This additional amount serves two other purposes as well. First, it
provides the capital to fund future additions, thereby reducing debt.
Second, it allows rates to remain in effect for a longer period of time
as inflation increases operating expenses.
Since revenue requirements include contributions for the Major
Repair and Replacement Fund, the target margin has been reduced
from $500,000 included in earlier drafts to $300,000. This
represents approximately 2 percent of operating costs when
wholesale power purchases are included.
It is important to note that the revenue requirements are relatively fixed in
nature. Certain costs may be influenced by the number of customers; but
even then, these costs are fixed once the infrastructure is built. It is only
billing-related costs that are directly influenced by the number of customers
at any one time, and these costs represent a very small amount of the total
revenue requirements. Thus, the revenue requirements will not be influenced
by the level of energy sales or the number of customers.
IV. Billing Determinants/ Revenue Requirements Page 18
213
Table 6
SES COST OF SERVICE STUDY
Revenue Requirements
2022 2023 Adjustment 2023 2024 2025 2026
Budget Budget
Transmission Ops
Labor and Benefits 49,078 78,600 78,600 127,039 130,215 133,471
Other 826,700 512,500 512,500 620,090 225,592 546,420
Subtotal 875,778 591,100 591,100 747,129 355,807 679,891
Distribution O&M
Labor and Benefits 69,268 81,745 81,745 132,122 135,425 138,811
Other 33,825 30,000 30,000 32,710 33,528 34,366
Subtotal 103,093 111,745 111,745 164,833 168,954 173,177
Wholesale Power Costs
Chugach 2,322,950 2,393,000 (2,393,000) - - - -
Chugach Fuel 3,600,000 3,708,000 (3,708,000)
Subtotal 5,922,950 6,101,000 (6,101,000) - - - -
Work Orders
Labor and Benefits 229,684 108,050 108,050 174,639 179,004 183,480
Other (105,025) - - (53,825) (55,171) (56,550)
Subtotal 124,659 108,050 108,050 120,913 123,834 126,929
General Operations
Labor and Benefits 1,728,560 1,314,716 1,314,716 2,124,943 2,178,066 2,232,518
Gen Fund Admin Fee 1,005,612 1,035,780 1,035,780 1,035,780 1,035,780 1,035,780
PILT - - 1,000,000 1,000,000 1,025,000 1,050,625 1,076,891
Major Repair/Repl Fund - - - - 350,000 358,750 367,719
Depreciation 2,560,132 1,585,000 - 1,550,591 1,839,582 1,934,631 1,714,826
Other 2,115,881 1,688,550 (185,000) 1,503,550 1,714,562 1,755,955 1,798,383
Subtotal 7,410,185 5,624,046 815,000 6,404,637 8,089,866 8,313,807 8,226,117
Administration
Labor and Benefits 415,129 354,996 - 354,996 573,771 588,115 602,818
Other 462,665 161,950 161,950 181,363 184,868 188,460
Subtotal 877,794 516,946 516,946 755,134 772,983 791,278
Debt Service
Interest Expense 154,450 586,700 586,700 579,700 722,525 702,789
Principal Payments 19,000 200,000 (200,000) - - - -
Other 20,903 25,403 23,916 23,916 23,916 23,916
Subtotal 194,353 812,103 (200,000) 610,616 603,616 746,441 726,705
Other Operating Expenses(Revenues)
Turn on Fees (21,800) (18,077) (18,077) (19,939) (19,939) (19,939)
Equipment Rental (2,125) (5,430) (5,430) (3,778) (3,778) (3,778)
Join Pole Use (10,800) (10,212) (10,212) (10,506) (10,506) (10,506)
Work Order Revenue (30,000) (30,000) (30,000) (30,000) (30,000) (30,000)
Collection of Doubtful Accts (550) (275) (275) (275)
Subtotal (65,275) (63,719) (63,719) (64,497) (64,497) (64,497)
Non-Operating Expenses(Revenue (49,100) (117,541) (117,541) (104,191) (104,191) (104,191)
Target Margin - - 300,000 300,000 300,000 300,000
Revenue Requirements 15,394,437 13,683,730 (5,486,000) 8,461,834 10,612,704 10,613,138 10,855,410
IV. Billing Determinants / Revenue Requirements Page 19
214
V. REVENUE ADEQUACY AND COST ALLOCATION
ADEQUACY OF EXISTING RATES
By applying the existing rates to the billing determinants previously shown in
Table 4, revenues can be projected over the study period. These revenues,
shown below in Table 7, are then compared to the projected revenue
requirements. As seen in Table 7, rates should be increased immediately by
$0.060/kilowatt-hour by the end of this year followed by $0.003 two years
hence.
Table 7
SES COST OF SERVICE STUDY
Adequacy of Existing Rates
2023 2024 2025 2026
Residential
Customer Charge $ 553,097 $ 553,097 $ 553,097 $ 553,097
Energy 1,599,325 1,599,325 1,599,325 1,599,325
Subtotal 2,152,422 2,152,422 2,152,422 2,152,422
Small Gen Svc
Customer Charge 290,685 290,685 290,685 290,685
Energy 968,151 968,151 968,151 968,151
Subtotal 1,258,836 1,258,836 1,258,836 1,258,836
Harbor
Customer Charge 14,059 14,059 14,059 14,059
Energy 205,992 205,992 205,992 205,992
Subtotal 220,052 220,052 220,052 220,052
Large Gen Svc
Customer Charge 41,974 41,974 41,974 41,974
Energy 1,042,473 1,042,473 1,042,473 1,042,473
Demiand 1,451,554 1,451,554 1,451,554 1,451,554
Subtotal 2,536,001 2,536,001 2,536,001 2,536,001
Industrial
Customer Charge 3,600 3,600 3,600 3,600
Energy 391,501 400,296 409,092 409,092
Demiand 662,570 693,157 723,840 723,840
Subtotal 1,057,671 1,097,053 1,136,532 1,136,532
Lights 77,106 77,106 77,106 77,106
Total $ 7,302,086 $ 7,341,469 $ 7,380,948 $ 7,380,948
Revenue Requirement $ 8,461,834 $ 10,612,704 $ 10,613,138 $ 10,855,410
Surplus (Deficiency) $ (1,159,747) $ (3,271,235) $ (3,232,190) $ (3,474,462)
Required Increase ($/kWh)
From Existing Rates $ 0.021 $ 0.060 $ 0.059 $ 0.063
From Previous Year $ 0.021 $ 0.038 $ (0.001) $ 0.004
V. Cost Allocation and Results 20
215
To gain an insight into how these rate increases might be lessened, every
$500,000 of revenue requirements equates to slightly under $0.01/kilowatt-
hour. Steps that the City or SES might implement to lessen the required rate
increases are discussed in the next section.
COST OF SERVICE
While the overall rates must be adjusted, the question then becomes how
should the rates within the various rate classes be adjusted? Should they all
be adjusted by the same amount, the same percentage, or a different amount
for each rate class?
The allocated cost of service analysis provides insight into this. But, it must
be stressed that cost-of-service studies are not an exact science.
Although the NARUC Manual was established to set forth guidelines in
classifying the various revenue requirements, the process requires estimates
of certain allocators to be made. Furthermore, customers in one rate class
are "generally" in different locations than others, but geographical boundaries
are typically blurred. Finally, the process is based on a snapshot in time, and
usage patterns and relative usage change over time.
All in all, the results should not be taken as exact numbers but rather
guidance on whether rates are set too high or too low.
ALLOCATION FACTORS
As described in Section II of this report, demand-related expenses are
allocated based on estimates of each class'contribution to the coincident peak
and the non-coincident peak. For a large utility, these estimates are
developed through detailed load research where the hourly usage of customer
sample groups are monitored over at least a year. From this, estimates can
then be made for rate classes as a whole.
This load research, however, is relatively expensive, and the benefits of
gaining the data are quickly eroded for small utilities such as SES. Therefore,
other methods are used, such as reviewing billing demand records for large
customers and using load research data from nearby utilities.
For this analysis, the load research data developed by Anchorage Municipal
Light& Power ("AML&,P") prior to its merger with Chugach is used as guidance
and modified where deemed appropriate. It must be remembered that load
research is used to estimate load patters, not actual loads. Although AML&P
is much larger than the SES system, its compactness is believed to make it a
better indicator of SES load patterns than other utilities such as Chugach or
Homer Electric. The derivation of coincident and non-coincident peaks is
V. Cost Allocation and Results 21
216
summarized in Appendix D, and the sum of the calculated monthly coincident
peaks is within 1 percent of the actual amount.
SCENARIO DESCRIPTIONS
The cost allocation analysis was conducted using a single year of revenue
requirements. A multiple year analysis would result in over-collection in some
years and under-collection in others. In anticipation of selling the utility again
being put before the voters, two scenarios were investigated.
Scenario 1: Retention of the utility and bringing it up to date. Revenue
requirements are based on those projected for 2024, the initial year of
the increased labor expenses. Table 7 showed that a small increase
would be required the following year.
Scenario 2: Sale of the utility with no staff additions or major capital
improvements. Revenue requirements are based on those projected for
2023. Since the approval process for the sale of the utility would take
at least a year, inclusion of the target margin in the revenue
requirements is critical to maintain adequate revenues as inflation cuts
into margins during the approval process.
RESULTS
The results are summarized in the following tables, and details of the results
are provided in the Appendix. Specific rate options are discussed in the
following section.
Scenario 1 - Utility Retention (Table 8): Rates must be increased by an
average of $0.060/kilowatt-hour to meet revenue requirements. All
rate classes must be increased with those of the Residential and
Industrial being the largest increase.
The $0.060 increase should be implemented in 2023. A further rate
increase of approximately $0.003/kilowatt-hour would be required at
the beginning of 2026 absent cost cutting measures that might be
implemented (discussed in the next section).
Scenario 2 - Utility Sale (Table 9): Rates must be increased by an
average of$0.021/kilowatt-hour to meet revenue requirements. Again,
the largest increases are found with the Residential and Industrial rate
classes.
Since revenue requirements are based on the 2023 budget, the increase
should be implemented in 2023 even if the utility is to be sold. Since
the approval process for the sale will take at least a year, a rate increase
is required to maintain adequate revenues during this process.
V. Cost Allocation and Results 22
217
Table 8
SES COST OF SERVICE STUDY
Scenario 1 (Utility Retention)Allocation Results
Street
Residential San Gen Svc Boat Harbor Lg Gen Svc Industrial Total
Lights
Allocated Cost of Service
Energy $ 1,643 $ 911 $ 195 $ 2,007 $ 979 $ 7 $ 5,742
Demand
12 CP 1,267,132 1,053,974 153,762 2,978,394 1,389,160 11,379 6,853,801
NCP 420,949 233,758 103,079 576,587 290,173 7,578 1,632,124
Customer
Meters 1,536,900 422,806 20,449 58,278 2,211 4,421 2,045,065
Meter Cost 4,933 1,357 66 281 14 14 6,665
Direct
SL Direct - - - - - 39,853 39,853
Direct - - 29,455 - - - 29,455
Total $ 3,231,557 $ 1,712,805 $ 307,006 $ 3,615,546 $ 1,682,537 $ 63,253 $ 10,612,704
Revenues From Existing Rates
Customer $ 553,097 $ 290,685 $ 14,059 41,974 3,600 903,415
Energy 1,599,325 968,151 205,992 1,042,473 400,296 4,216,237
Demand 1,451,554 693,157 - 2,144,710
Street/YardLights 77,106 77,106
Total $ 2,152,422 $ 1,258,836 $ 220,052 $ 2,536,001 $ 1,097,053 $ 77,106 $ 7,341,469
Allocated Cost of Service 3,231,557 1,712,805 307,006 3,615,546 1,682,537 63,253 10,612,704
Surplus(Deficiency) $ (1,079,135) $ (453,969) $ (86,954) $ (1,079,545) $ (585,484) $ 13,853 $ (3,271,235)
Required Adjustment
Percentage 50.1% 36.1% 39.5% 42.6% 53.4% -18.0% 44.6%
S1kW'h 0.069 0.052 0.020 0.056 0.063 0.060
V. Cost Allocation and Results 23
218
Table 9
SES COST OF SERVICE STUDY
Scenario 2 (Utility Sale)Allocation Results
Street
Residential Sm Gen Svc Boat Harbor Lg Gen Svc Industrial Total
Lights
Allocated Cost of Service
Energy $ 879 $ 487 $ 105 S 1,074 $ 524 $ 4 $ 3,073
Demand
12 CP 1,008,842 839,134 122,419 2,371,284 1,105,996 9,060 5,456,735
NCP 337,976 187,682 82,761 462,935 232,977 6,085 1,310,415
Customer
Meters 1,233,122 339,235 16,407 46,759 1,774 3,548 1,640,845
Meter Cost 2,654 730 35 151 8 8 3,586
Direct
SL Direct - - - - - 29,347 29,347
Direct - - 17,833 - - - 17,833
Total $ 2,583,473 $ 1,367,268 $ 239,561 $ 2,882,203 $ 1,341,278 $ 48,050 $ 8,461,834
Revenues From Existing Rates
Customer $ 553,097 $ 290,685 $ 14,059 41,974 3,600 903,415
Energy 1,599,325 968,151 205,992 1,042,473 391,501 4,207,441
Demand 1,451,554 662,570 - 2,114,124
Street/YardLights 77,106 77,106
Total $ 2,152,422 $ 1,258,836 $ 220,052 $ 2,536,001 $ 1,057,671 $ 77,106 $ 7,302,086
Allocated Cost of Service 2,583,473 1,367,268 239,561 2,882,203 1,341,278 48,050 8,461,834
Surplus(Deficiency) $ (431,052) $ (108,433) $ (19,509) $ (346,202) $ (283,608) $ 29,056 $ (1,159,747)
Required Adjustment
Percentage 20.0% 8.6% 8.9% 13.7% 26.8% -37.7% 15.9%
S/kWh 0.027 0.012 0.004 0.018 0.030 0.021
V. Cost Allocation and Results 24
219
VI. CONSIDERATIONS AND OPTIONS
Even though the path forward regarding SES rates will depend on whether
the utility is sold, some form of rate increase must be implemented this year.
Sale of the utility requires an average increase of $0.02 1/kilowatt-hour,
whereas a $0.060/kilowatt-hour average increase is required if the utility is
retained. Two overall questions must be considered by the City regarding
these adjustments:
1. Should the revenue requirements be adjusted from that used in the
analysis?
2. Should the rate increase be applied on an equal basis to each rate class
or should the rates be moved closer to their respective allocated cost of
service?
REVENUE REQUIREMENTS
There are a number of actions that can be implemented that would result in
reduced revenue requirements. Several of these, however, are policy decisions
that would impact rates of other City services. Therefore, these actions are
focused more toward Scenario 1 - Utility Retention. Every $1 million
reduction (or addition) in revenue requirements represents a
$0.018/kilowatt-hour change in the required adjustment.
PILT: The analysis is based on a PILT assessment of$1,000,000. The
rate of assessment (8 percent of revenues) could be lowered.
Administrative Fee: The analysis uses the budgeted amount of
$1,035,780 for each year of the study period. How this was developed
could not be determined, and the total amount assessed to each
department and how it is assessed should be reviewed by the City.
Target Margin: Originally, a $500,000 target margin was investigated;
but in an attempt to lessen the impact on ratepayers, a margin of
$300,000 was used for each year. Further reductions are not
recommended, especially for Scenario 2 - Utility Sale. Revenue
requirements for that scenario are based on the 2023 budget, and
inflation will increase costs during 2024 when the sale is progressing
through the approval process.
Increased Costs for Utility Retention. This analysis is based on
preliminary estimates of the increased expenses required for long-term
safe and reliable operations. A working group was recently formed to
investigate this in more detail, and revenue requirements may be more
or less than that used.
VI. Considerations and Options 25
220
RATES AND COST OF SERVICE
The analysis showed that all rates must be increased, with Residential and
Industrial being the farthest from the allocated cost of service. Should the
rate adjustment be applied on an across-the-board basis (same $/kWh
increase to all or same percentage to all), or should the rate adjustment to
each class differ in an attempt to move them closer to cost-of-service? As
noted before, cost-of-service studies are not an exact science, and striving for
a zero deviation between class revenues and allocated cost of service is not
warranted.
Scenario 1 - Utility Retention showed both Residential and Industrial being
furthest from cost of service. However, the required adjustments of 50 percent
and 53 percent are quite high, and having other rate classes sharing part of
it may be in order.
For Scenario 2 - Utility Sale, it is recommended that the average rate
adjustment of $0.02 1/kilowatt-hour be applied to all rate classes. SES will
eventually be blended in with the purchasing utility's own rate classes and
cost of service, and an across-the-board increase might lessen rate instability.
RATE OPTIONS
Scenario 1 - Utilitu Retention
Several options are presented in Table 10 with the monthly increase for the
average customer in each rate class shown. The average for the Boat Harbor
is based on 28 meters, whereas there are numerous end-use customers for
each meter. Other options certainly exist and can be explored as requested.
Option 1. Increase each rate by $0.055/kilowatt-hour. This results in
revenues meeting all revenue requirements but with a very small
margin. This option is not recommended unless the revenue
requirements can be lowered through policy changes described earlier.
Option 2. An across-the-board increase of$0.059/kilowatt-hour. This
increases the margin to approximately $269,000, a bit less than the
target margin of $300,000. If no other cost-saving measures are
implemented, this option would most likely allow rates to be held
constant until 2026.
Option 3. An across-the-board increase for the full $0.060/kilowatt-
hour. The Residential rate class is within 92 percent of its allocated
cost of service with the other rate classes making up the difference.
Option 4. Implementing rates that move each class closer to cost of
service while attempting to lessen the large increase required for
Residential. All are within 5 percent of the allocated cost-of-service,
which is considered reasonable.
VI. Considerations and Options 26
221
Scenario 2- Utility Sale
As previously stated, it is recommended that the full $0.02 1/kilowatt-hour
increase be implemented on an across-the-board basis. This scenario is
shown at the bottom of Table 10.
Table 10
SES COST OF SERVICE STUDY
Rate Options and Bill Impact
Boat Harbor Street
Option Residential Sm Gen Svc (28 meters) Lights Lg Gen Svc Industrial Total
Scenario 1-Utility Retention
1.1 Increase all by$0.055/kWh
Increase($/kWh) $ 0.055 $ 0.055 $ 0.055 $ 0.055 $ 0.055 $ 0.055
Added Revenues $ 864,170 $ 479,020 $ 102,716 $ 1,055,618 $ 514,876 $ 3,723 $ 3,020,123
SES Margins $ 48,898
Avg Monthly Increase $ 34.53 $ 69.57 $ 308.46 $ 1,112.35 $ 14,302.11 $ 51.71
Percent of Cost of Service 90% 99% 101% 98% 95%
1.2 Increase all by$0.059/kWh
Increase($/kWh) $ 0.059 $ 0.059 $ 0.059 $ 0.059 $ 0.059 $ 0.059
Added Revenues $ 927,018 $ 513,858 $ 110,186 $ 1,132,390 $ 552,321 $ 3,994 $ 3,239,768
SES Margins $ 268,533
Avg Monthly Increase $ 37.04 $ 74.63 $ 330.89 $ 1,193.25 $ 15,342.26 $ 55.47
Percent of Cost of Service 92% 101% 103% 100% 97%
1.3 Increase all by$0.06/kWh
Increase($/kWh) $ 0.060 $ 0.060 $ 0.060 $ 0.060 $ 0.060 $ 0.060
Added Revenues $ 942,730 $ 522,568 $ 112,054 $ 1,151,583 $ 561,683 $ 4,062 $ 3,294,680
SES Margins $ 323,445
Avg Monthly Increase 5 37.67 $ 75.90 $ 336.50 $ 1,213.47 $ 15,60230 $ 56.41
Percent of Cost of Service 92% 102% 104% 101% 98%
1.4 Move to Cost of Service
Increase($/kWh) S 0.065 $ 0.060 $ 0.050 $ 0.055 $ 0.060 $ 0.060
Added Revenues $ 1,021,291 $ 522,568 $ 93,378 $ 1,055,618 $ 561,683 $ 4,062 $ 3,258,600
SES Margins $ 287,365
Avg Monthly Increase $ 40.81 $ 75.90 $ 280.42 $ 1,11235 $ 15,602.30 $ 56.41
Percent of Cost of Service 95% 102% 98% 98% 98%
Scenario 2-Utility Sale
2.1 Increase all by$/kWh
Increase($/kWh) $ 0.021 $ 0.021 $ 0.021 $ 0.021 $ 0.021 $ 0.021
Added Revenues $ 329,956 $ 182,899 $ 39,219 $ 403,054 $ 196,589 $ 1,422 $ 1,153,138
SES Margins $ 332,773
Avg Monthly Increase 5 13.18 $ 26.56 $ 117.77 $ 424.71 $ 5,460.81 $ 1974.
Percent of Cost of Service 94% 103% 106% 100% 91%
VI. Considerations and Options 27
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VII. SUMMARY AND RECOMMENDATIONS
SUMMARY
The last cost-of-service study for SES was completed in 2021. From that
study, an Industrial rate class was established and the Alaska SeaLife Center
was moved from its special contract to the Industrial rate.' Residential rates
were also increased, but both the Residential and Industrial rates were less
than their allocated cost of service.
Since the time of that study, deferred maintenance items have been completed
and debt has been taken on to complete several capital additions. Perhaps
more important, staffing levels have been identified to be insufficient to
maintain on-going reliable operations. That, coupled with the need for higher
salaries to attract qualified personnel, could add nearly $1 million in
increased operating costs.
All of this, combined with the high general inflation that has occurred over
the past two years, has created a potential shortfall in utility revenues.
Accordingly, a cost-of-service study was conducted to investigate the
adequacy of existing rates and how close each rate class was to its allocated
cost of service.
Two separate scenarios were investigated:
1. Retaining the utility and implementing measures to ensure long-term
reliability. This assumed staff would be expanded, salaries increased,
and capital improvements continued to be made.
2. Not implementing these measures in anticipation of selling the utility
in the very near future.
SCENARIO I -UTILITY RETENTION
The analysis found that retaining the utility with the increased costs resulted
in a revenue shortfall of $0.060/kilowatt-hour for 2024 and an additional
$0.003/kilowatt-hour in 2026 (Table 7). Rates for all rate classes were less
than cost-of-service, but Residential and Industrial rates required the largest
increase (Table 8).
Included in the revenue requirements for this scenario were a target margin
of$300,000 per year and transfer to the City's General Fund of approximately
$1 million each for Payment in Lieu of Taxes ("PILT") and the City
' The SeaLife Center is transitioning to the full Industrial rate over a period of time with the full
rate being implemented January 2025.
VII. Summary and Recommendations 28
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Administrative Fee. The $300,000 target margin represents a reduction from
that presented to the City Council on September 11, and further reductions
are not recommended. The cost of increased labor costs are based on
preliminary estimates and do not include capital improvements that might be
necessary to accommodate the increased staffing. PILT and the
Administrative Fee can also be lowered, but presumably any reduction from
SES transfers would have to be made up from other sources. As point of
reference, a reduction of $1 million in revenue requirements equates to
approximately $0.018/kilowatt-hour.
SCENARIO 2 -UTILITY SALE
Although the increased labor costs and capital spending were not included in
this scenario, a revenue shortfall equal to $0.021/kilowatt-hour still exists
(Table 9). This increase is due to the debt and depreciation associated with
the recent capital improvements and general inflation over the past two years.
As with Scenario 1, all rates for all classes are currently less than cost of
service with Residential and Industrial requiring the largest adjustment.
Options to reduce the revenue requirements are limited for this scenario.
There would be insufficient time to investigate the effect of reducing the PILT
or Administrative Fee. Furthermore, a reduction in the target margin is not
recommended since on-going operations and maintenance costs will increase
with inflation during the approval process if the utility is sold.
RECOMMENDATIONS
The City's course of action regarding SES rates will depend on the decision to
sell the utility. The following recommendations are made for the City's
consideration.
SCENARIO 1 -UTILITY RETENTION
1. Implement a rate increase averaging at least $0.059/kilowatt-hour
(Options 1.2 in Table 10). This would be sufficient until 2026 when a
smaller increase of $0.003/kilowatt-hour is projected to be required,
dependent on any cost-saving measures that might be implemented.
2. Investigate the methodologies used in developing the PILT and
Administrative Fee and how any reduction to SES would be made up.
SCENARIO 2 -UTILITY SALE
1. Implement a rate increase of $0.021/kilowatt-hour on an across-the-
board basis.
2. Reductions of the target margin in an attempt to lower the rate increase
is not recommended for reasons stated herein.
WI. Summary and Recommendations 29
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3. Investigate how proceeds from the sale could offset the loss of SES
payments of PILT and the Administrative Fee and perhaps memorialize
the use of such proceeds.
WT Summary and Recommendations 30
225